A Challenging Supply-Demand Outlook for LNG Producers: The Evolving LNG Market

A Challenging Supply-Demand Outlook for LNG Producers

The Evolving LNG Market

By Iván Martén and Juan Vázquez

The next several years will be difficult for producers of liquefied natural gas (LNG). Production capacity will expand significantly, but demand growth, even if relatively strong—our base scenario calls for annual growth of 5% to 6% from 2015 to 2025—will not be sufficient to absorb all the new supply. This supply-demand dynamic translates into significant downward pressure on already depressed LNG spot prices—and thus on the revenues and profits of LNG producers.

Players seeking to weather this environment successfully and position themselves optimally for the longer term will need to take a number of steps. Most critically, they will need to materially reduce the development costs of new liquefaction projects.

Today’s Natural Gas Market

To understand the dynamics of, and prospects for, the global LNG market, it is helpful to examine the current backdrop for natural gas. Natural gas is what we refer to as a triple-A resource, one that is abundant, available, and affordable. Driven in large measure by the shale gas revolution in the United States, the supply of natural gas has risen significantly over the past several years. Natural gas is also becoming increasingly available, with growing numbers of countries finding reserves within their borders. And natural gas is cheaper, based on its levelized cost of energy, than many renewables, including solar thermal and solar photovoltaic energy, and not substantially more expensive than coal. Additionally, natural gas is environmentally friendly compared with other fossil fuels—its carbon emissions are roughly half those of coal.

Given these characteristics, it is no surprise that global demand for natural gas is climbing strongly, especially relative to other fossil fuels. Demand is projected to rise 1.4% per year from 2013 through 2025, according to the International Energy Agency, versus 0.4% growth for coal and 0.6% for oil. This growth is expected to be propelled in large measure by particularly strong increases in demand from China, India, and the Middle East. But any estimate of demand growth in the coming years could prove conservative if countries and industries turn more aggressively to natural gas to meet their emissions objectives—and there is a good possibility that this will occur. (See “Will Natural Gas Demand Soar as Emissions Reduction Intensifies?” BCG article, May 2016.)

LNG has long demonstrated strong demand growth relative to natural gas and other fossil fuels. LNG demand grew at an annual rate of 6.2% from 1990 through 2015, compared with 2.3% for natural gas and 1.4% for oil. Its share of the natural gas market has risen in parallel. In 2002, LNG represented 7% of the total natural gas supply; in 2015, it represented 16%.

A Pending Surge in LNG Production Capacity

The global supply of LNG expanded at 9% per year from 2001 through 2011. Since then, supply has been essentially flat, hovering at 320 to 325 billion cubic meters per annum (bcma), despite net growth of about 40 bcma in liquefaction capacity from 2011 through 2015. (This growth in liquefaction capacity has been offset by reduced utilization of existing capacity due to two factors: technical problems at some facilities, such as the Angola LNG plant, in Soyo, Angola, and the ramp-up of projects that came online during this period, in particular a number of projects in Australia.)

Supply stands to expand substantially in the next several years, however. There are 13 liquefaction plants that have secured a final investment decision (FID) and are currently under construction; these will commence operation within the next three to five years. Collectively, these plants will have a production capacity of 185 bcma, an amount equivalent to 57% of the world’s total production in 2014 and close to the total growth in LNG production that occurred during the last 13 years.

In addition to these projects, there is an additional 270 bcma of potential liquefaction capacity in projects under consideration. However, we believe these projects are relatively unlikely to come to fruition in the near term for two reasons:

  • Relatively Low LNG Spot Prices. To finance the development of liquefaction projects, which are normally multibillion-dollar investments, LNG producers rely on long-term supply contracts with customers. These contracts commit customers to off-taking substantial amounts of LNG at a price linked to the price of a commodity, typically oil. (Contract prices are generally 13% to 15% of the price of Brent crude oil on a delivered ex-ship basis—that is, the price paid for LNG at the destination port before regasification.) Customers are requesting contract prices that are competitive with LNG spot prices, which are currently quite low in comparison.1 Notes: 1 LNG spot prices are currently about $5 to $6 per million British thermal units (BTU) on a delivered ex-ship (DES) basis. This translates into a contract price of 12% to13% of the price of Brent crude.
  • High Breakeven Prices for New Liquefaction Projects. There are almost no new projects whose breakeven prices are lower than the LNG prices that consumers are currently willing to pay.2 Notes: 2 LNG spot prices of $5 to $6 per million BTU on a DES basis is equivalent to a free on board (FOB) price (the price paid at the liquefaction terminal) of between $4 and $5 per million BTU. This means that, in the current price environment, none of the proposed projects would be profitable, hence none is likely be developed. (See Exhibit 1.)

But the reality is that, despite these unfavorable economics, new projects will need to come online in the future to meet demand growth. The only real alternative for the industry, therefore, is to significantly reduce development costs and adapt them to the new pricing environment. To do this, it will need to focus on developing only the most competitive projects. (Brownfield developments in accessible areas tend to be much more competitive than greenfield developments in inaccessible ones, for example.) The industry will also need to implement structural solutions, such as adopting modular and/or standardized approaches to plant construction, reducing supply costs by fostering increased competition among suppliers, and embracing lean approaches to the entire development process.

How are these dynamics likely to play out? We have developed three scenarios for the evolution of global LNG supply capacity to 2025:

  • Base Scenario. Supply capacity rises to approximately 528 bcma in 2018 and 640 bcma in 2025. This scenario assumes a one-year delay in the launch of 8 of the less advanced of the 13 projects with FIDs, as well as the debottlenecking of liquefaction facilities in Qatar, the world’s largest supplier of LNG, and the addition of approximately 30 bcma in capacity from plants currently lacking FIDs that come online between 2020 and 2025.3 Notes: 3 Qatar’s government has the ability to debottleneck the country’s LNG production facilities. Successful debottlenecking could increase the country’s production capacity by up to 18 million tonnes per year.
  • Low Scenario. Supply capacity reaches roughly 516 bcma in 2018 and 587 bcma in 2025. This scenario assumes two-year delays in the launch of those same eight projects, a continuation of the status quo in Qatar, and no additional capacity from projects currently lacking FIDs. Liquefaction capacity is thus limited to existing capacity and to projects already under development.
  • High Scenario. Supply capacity climbs to 610 bcma in 2018 and 665 bcma in 2025. This scenario assumes no delays in the launch of any of the 13 projects with FIDs, as well as the debottlenecking of liquefaction facilities in Qatar and the addition of approximately 55 bcma in capacity from plants currently lacking FIDs that come online between 2020 and 2025.

Note that even the most conservative scenario calls for a substantial jump in production capacity compared with current levels. But will the demand support this?

Growing LNG Demand—but How Strong Will the Growth Be?

LNG demand grew from 150 bcma in 2002 to 327 bcma in 2011, a 9% annual rate of growth. But demand has been largely flat since then and has remained Asia-centric. Indeed, Asia accounted for 80% of the demand growth between 2002 and 2014. Japan, Taiwan, and South Korea represent more than 50% of current demand.

Demand growth is poised to resume its upward trend. Our base scenario assumes annual growth of 5% to 6% from 2015 through 2025, with demand ultimately reaching 571 bcma. The key drivers of this growth will be China, India, and Southeast Asia, which collectively will account for about 75% of total demand growth in that scenario. (See Exhibit 2.)

There are a number of uncertainties, though, that could lead to markedly higher or lower final demand. These include energy policies, economic growth, and competition from alternative fuels or sources of gas supply, such as domestic production or pipeline imports. Japan and China offer two examples:

  • Japan has announced its intention to restart 24 gigawatts of nuclear capacity in the near term. If the country were to fall short of this objective or, conversely, restart a greater amount of nuclear capacity, global LNG demand could be 30 bcma above or below our base scenario.
  • In China, pipeline imports of natural gas could reach between 90 and 160 bcma within the next ten years, compared with imports of 31 bcma in 2014. This makes it extremely difficult to predict with confidence how much LNG the country will need to import by 2025.

These and other variables make it difficult to project demand with a high degree of certainty. This is evident in the wide spread between the final-demand projections in our low and high scenarios, which call for demand of 421 and 719 bcma, respectively, in 2025. (See Exhibit 3.) This is a considerably larger spread than there is between our low and high scenarios for future supply.

Supply Versus Demand: Implications for LNG Producers

The upshot of this supply-demand picture is that there will be a surplus of LNG on the market for the next several years. We modeled low, base, and high scenarios for supply versus demand for 2018 and 2025; eight of the nine scenarios for 2018 indicated significant oversupply, with our base scenario indicating an oversupply of 61 bcma, or approximately 10 bcma more than Europe’s total LNG demand in 2015. (See Exhibit 4.) This amount exceeds expected demand in 2018 by 15%. (It is worth noting that by 2025, supply will have adjusted to demand and the surplus will have vanished. In fact, our base scenario for 2025 indicates an undersupply of 28 bcma.)

These dynamics will coincide with growing liquidity in the LNG market. (See Exhibit 5.) Spot and short-term volumes of LNG have risen steadily and significantly, climbing from 25 bcma in 2005 to about 100 bcma in 2015. This growth is expected to continue, with volume in 2025 exceeding 200 bcma.

As a consequence of this oversupply, LNG spot prices will remain under considerable pressure for some time. The key question is, How low will spot prices go?

A number of factors will ultimately act as a floor under prices. One is the likelihood that suppliers with broad portfolios will actively curtail the amount they produce—even if their production costs are below the level of spot prices—in order to keep spot prices from going so low that they trigger a wave of calls by long-term customers to renegotiate existing contracts. Russia, for example, between 2013 and 2014 reduced its exports to European markets by nearly 10%, from 162 to 148 bcm, in order to ease downward pressure on spot prices in the European market resulting from oversupply. This reduced pressure on the country’s portfolio of long-term contracts.

There are also two factors that will limit spot price declines in cases of oversupply. The first comes from the supply side. There is 90 bcm of LNG scheduled to come online during the next five years from the US. But US production facilities will curtail production if spot prices reach a level that is financially disadvantageous to off-takers (that is, buyers who are committed to purchasing certain volumes). This situation can arise because of the nature of the contracts that underpin these projects. The projects are grounded on contracts between off-takers and liquefaction “tollers” (infrastructure companies that own liquefaction facilities in the US) that give off-takers the right, but not the obligation, to off-take volumes. The contracts do, however, oblige off-takers to pay a tolling fee regardless of whether they off-take volumes or not. In situations where spot prices are such that off-takers that off-take volumes would incur a loss greater than the tolling fee—that is, when spot prices for LNG delivered ex-ship (DES) are less than 115% of Henry Hub prices plus transportation costs—off-takers would likely decide not to off-take volumes and instead just pay the tolling fee. In such cases, these facilities will not be producing any LNG. Assuming a Henry Hub price of around $5 per million BTU, this dynamic will provide spot price floors of $7 per million BTU (DES) in Europe and $9 per million BTU (DES) in the Far East. These floors will put a brake on oversupply in the market.

The second factor that will act as a floor under LNG spot prices in cases of oversupply comes from the demand side. Demand could see a strong boost in Europe, and ultimately globally, if LNG spot prices fall to or below the level at which gas can compete effectively against coal given both their marginal costs. If spot prices reach this level (about $4.6 per million BTU in Europe, assuming a carbon price of $25 per ton and a coal price of $45 per ton), there will likely be a significant jump in LNG demand as LNG increasingly supplants coal as a generation source. (See Exhibit 6.)

In the context of increased liquidity, these low spot prices could prompt growing numbers of customers to ask for renegotiation of their existing long-term LNG contracts. This would be especially probable in an environment of high oil prices (in which long-term contract prices that are indexed to Brent prices would increase substantially) coupled with a significant oversupply of LNG in the market.

A Must-Do: Reduce LNG Development Costs

High prices and booming demand for LNG in recent years have allowed industry players to grow lax in managing development costs. Indeed, costs for newly launched projects, which began to trend upward in 2000, have shown a sharp upward slope since 2010. This was not a make-or-break issue for producers when prices and demand were supportive. But it is of critical importance today and will remain so as producers wrestle with the environment we’ve described. Producers can no longer pursue development for development’s sake, sometimes opting for projects in remote areas that have poor infrastructure, scarce key resources, and high construction costs. Rather, they must narrow their focus to only the most competitive projects and implement cost management measures to materially reduce development costs.

There are several steps producers can take to put themselves on the right path. These include the following:

  • Develop modular and/or standardized approaches to plant construction. The industry has evolved toward the construction of very large, one-of-a-kind plants that have limited potential for standardization. Companies could potentially reduce construction costs considerably by turning to smaller units that permit modular plant construction and more standardization.
  • Foster competition among suppliers. In recent years, the industry has been characterized by limited competition among suppliers, especially in such critical components as refrigeration compressors and large heat exchangers. By fostering competition and supporting a larger supplier base, the industry could put downward pressure on prices. This would be facilitated by increased standardization of plants.
  • Rethink the company’s technology strategy. Industry participants have emphasized new technologies that have boosted scale and thermal efficiency. These complex technologies, however, are very expensive and relatively difficult to standardize. Currently, the greater efficiency that they deliver also translates into relatively low value, given depressed LNG spot prices. Producers must therefore reassess these technologies from a cost-benefit perspective.
  • Encourage cooperation among operators. Historically, there has been limited cooperation among developers; independent plants have been built side by side, resulting in substantial duplication. A more cooperative approach, one that leverages shared facilities, could optimize design and construction spending and generate meaningful reductions in capital and operational spending.
  • Implement lean approaches across the entire development process. The industry has so far placed limited emphasis on lean approaches. But these have led to reductions of as much as 30% in development costs in other industries, such as mining and a range of civil works. LNG developers need to think about how they can deploy lean approaches more broadly.
  • Simplify the company’s approach to the project design phase. LNG developers have typically used multiple front-end engineering and design firms, and complex contracting practices, in project design. This has often increased project length and management costs. A simpler, streamlined approach could lead to a shorter development schedule and lower costs.
  • Support the development and standardization of floating LNG technology. The LNG industry is in the early stages of developing and testing offshore liquefaction. Once the technology has been proven, industry participants will need to work to standardize the process before its full potential value can be realized.

The backdrop for LNG producers will be challenging for the next several years. Surging supply will weigh heavily on already depressed LNG spot prices, materially squeezing producers’ revenues and profits. But producers can take steps that will help them negotiate the challenges and position themselves to thrive once the industry’s supply-demand balance becomes more favorable. Most critically, they must work to drive down the development costs of new liquefaction projects by deploying standardized approaches to plant construction, fostering competition among suppliers, and adopting lean approaches to the entire development process.

This report is the first in a planned series of annual reports on the evolving LNG market. Each report will analyze the supply-demand environment using BCG’s proprietary LNG market model and discuss issues relevant to the industry.


The authors are grateful to Luis del Barrio and Lluis Bori for their support in developing the analyses.

A Challenging Supply-Demand Outlook for LNG Producers